An Investigation of Asphaltene Instability Under Nitrogen Injection

Abstract

As a part of an integrated improved oil recovery project, it was required to evaluate asphaltene formation arising from contacting nitrogen gas with the reservoir fluid. This paper discusses the experimental work associated with the asphaltene evaluation. The subject reservoir was known to have operational problems due to asphaltene precipitation during primary production. Hence, laboratory experiments using the transmittance of an optimized laser light in the near infrared (NIR) wavelength (~1600 nm) were used to first define the pressure-temperature regions of asphaltene instability of the reservoir fluid. Subsequently, several light transmittance experiments were conducted to evaluate the asphaltene instability regions by contacting various molar concentrations (5, 10, & 20%) of nitrogen gas with the reservoir fluid. Also, measurements were conducted to quantify the bulk precipitation of asphaltene with various molar concentrations of nitrogen. Results indicated that nitrogen gas aggravated the asphaltene instability, and also, increased the bulk precipitation amount with increasing concentrations of nitrogen gas in the reservoir fluid. The aggravated asphaltene instability could potentially nullify any expected benefits of improved oil recovery with nitrogen injection as pressure maintenance. Introduction Reservoir A has been under production with primary depletion for more than 20 years. The reservoir performance indicated minimal acqufier support and the reservoir pressure is expected to decline below the saturation pressure soon. Hence, a feasibility study was undertaken to evaluate the potential of improved oil recovery by pressure maintanance using nitrogen. A summary of the reservoir ‘A’ fluid properties is provided in Table 1. These properties confirm a typical black-oil reservoir fluid. Properties of note for the stock tank oil include a n-C7 insoluble asphaltene content of 1.4% (w/w) and a wax content of 1.2% (w/w) (UOP 46–64). The wax content did not appear to raise any concern, as there was no evidence of operational problem in the field related to wax. However, the subject reservoir was known to have operational problems due to asphaltene precipitation during primary production. Hence, it was necessary to evaluate the mechanisms of asphaltene formation arising from contacting nitrogen gas with the reservoir fluid. Asphaltenes are high molecular weight organic fractions of crude oils that are soluble in toluene, but are insoluble in alkanes (n-heptane/n-pentanes). Generally, asphaltenes tend to remain in solution or in colloidal suspension under reservoir temperature and pressure conditions. They may start to precipitate once the stability of the colloidal suspension is destabilized, which is caused by the changes in temperature and/or pressure during primary depletion.1 On the other hand, asphaltene have been reported to become unstable as a result of fluid blending (co-mingling) of fluid streams2 as well as by gas injection during Improved Oil Recovery (IOR) operations.3

A theoretically modified PC-SAFT equation of state for predicting asphaltene onset pressures at low temperatures

“…AOPs and Bubble-points predicted by O-PC-SAFT and mod-PC-SAFT for different asphaltene molecular weight values (MWasph). Panels (A) and (B) for Fluid 1 [this work]; panels (C) and (D) for Fluid 2 [153]; panels (E) and (F) for Fluid 3 [138]. Panels (A), (C), and (D) are for AOPs.…”

“…Nine reservoir fluids from the literature and one unpublished fluid are used to conduct the comparative calculations of AOPs using both the original PC-SAFT (O-PC-SAFT, or also called "GS-PC-SAFT" in this thesis), and its modified version presented here (i.e., mod-PC-SAFT). The fluids are denoted as follows: Fluid 1 [151], Fluid 2 [152], Fluid 3, Fluid 4 [151], Fluid 5 [153], Fluid 6 [151], Fluid 7 [154], Fluid 8 [155], and Fluid 9 [155]. Based on SARA analyses, these fluids covered an asphaltene content range from 0.80 to 16 wt.%.…”

“…Six petroleum reservoir fluids prone to precipitate asphaltenes, five from the literature and one not published before, were used to conduct predictive calculations of AOPs using both O-PC-SAFT and mod-PC-SAFT EoS. The fluids here modeled are denoted as follows: Fluid 1, Fluid 2 [153], Fluid 3 [138], Fluid 4 [186], Fluid 5 [154], and Fluid 6 [151]. Tables 2-6 to 2-8 show relevant information for Fluid 1.…”

“…In this work, six real petroleum reservoir fluids prone to precipitate asphaltenes were used to perform predictive calculations of AOPs and bubble-points (BPs) using the four PC-SAFT versions. These fluids are denoted as follows: Fluid 1 [165], Fluid 2 [153], Fluid 3 [138], Fluid 4 [186], Fluid 5 [113],…”

Nitrogen Injection Experience to Development Gas and Gas Condensate Fields in Rocky Mountains

“…For example, the injection of N2 into a gas condensate reservoir fluid will significantly increase the dew point pressure, which leads to liquid dropout of heavier hydrocarbons; Furthermore, contacting oil rim with nitrogen will strip the oil of light and intermediate components with effects of oil degradation and decrease of the solution gas-oil ratio (Vogel and Yarborough 1980;Shadizadeh et al 2006). Nitrogen injection also could cause asphaltene precipitation (Jamaluddin et al 2002). b.…”